"Albertans are currently
being appropriately compensated for the production and sale of
their oil, gas and oil sands resources."

- Alberta Royalty Review Advisory
Panel (January 29, 2016)

On January 29, 2016, the Alberta Government announced that it
will adopt the recommendations of the Royalty Review Advisory Panel
(the "Panel") from the Alberta at a Crossroads, Royalty
Review Advisory Panel Report (the
"Report") to modernize Alberta's
royalty framework. The common-sense adoption by the Alberta
Government of the Report prompted a collective sigh of relief
across Alberta and the energy industry.1

The Report is extensive and not only recommends a new modernized
royalty framework emulating a "revenue minus costs"
approach but provides an educational summary of how the energy
industry functions in the Province, how royalties are influenced by
market conditions, and the global competiveness of Alberta's
regime. Ultimately, the Report provides a harmonized royalty
strategy across all hydrocarbons, aimed at rewarding innovation,
efficiency and low-cost producers, while leaving oil sands
royalties substantively as-is but with more transparency and
financial reporting.

In addition to providing an overview of the new royalty
framework, this article provides a summary of the Panel's key
findings and a timeline for implementation. The new modernized
royalty framework ("MRF") requires a
"Calibration Period" to finalize specific formulas and
set up procedures for implementation. Those key formulaic and final
inputs are scheduled to be released by the Calibration Period
Committee on or before March 31, 2016.

A. KEY FINDINGS & CONCLUSIONS

1. Alberta's Oil and Gas Industry

The Report has educational undertones, and provides a clear and
concise overview of royalties in Alberta, including how commodity
prices and costs influence royalties, the relationship between
investment, industry's returns and royalties, and facts and
statistics to illustrate the discussion. Some of the noteworthy
facts and statistics are reproduced below.

The majority of Alberta's royalty
revenues come from oil sands production. In the 2014/15 fiscal
year, Alberta collected approximately $8.3 billion in total royalty
revenues ($5.1 billion from the oil sands).2

It is projected that for the 2015/16
fiscal year royalties will fall to approximately $2.8 billion (67%
decrease year-over-year).3

The past five years have seen costs
as a percentage of revenue rise beyond 80%. For the first time
since 1960, close to 100% of a barrel's value was consumed by
costs in 2012 and 2013.5

As of 2014, Alberta was the
eighth-largest producer of oil in the world, the eighth-largest
producer of natural gas in the world, and the ninth-largest
exporter of crude oil.6

2. New Challenges – A New Reality

In justification of its recommendations, the Panel discussed at
length the changing global energy landscape and the new challenges
facing Alberta's industry. Some of these "new
challenges" include:

Alberta's biggest customer is now
its biggest competitor.7 Over the last 7 years, the
dynamics with the United States (the
"U.S.") have shifted because the U.S. is
now producing huge volumes of oil and natural gas closer to key
markets at lower costs with more infrastructure for upgrading,
refining and transportationthan Canada.8 By way of
comparison, in 2014, average U.S. shale gas production was over 37
billion cubic feet (Bcf) per day and Alberta's average was
approximately 10 billion Bcf per day.9

Oil and gas are no longer scarce
resources.10 The same technological advances that
resulted in the U.S. resurgence in oil and gas production have had
the same effect around the world, and Alberta is now only one of
many places where significant amounts of oil and gas can be
produced.11

Patterns in oil and gas demand, while
strong, are also shifting as renewable sources of energy become
more economically viable.12

Canadian oil and gas producers have
higher average operating costs relative to the global
average.13

Alberta Energy has estimated that
discounts on Alberta's oil prices due to constrained market
access have led to the forfeiture of more than $6 billion in
royalties since 2010.14

Overlaying these dynamics is an
international tug-of-war for global oil market share. Saudi Arabia
and other members of the Organization of Petroleum Exporting
Countries have continued to maintain strong production in an effort
to push down global oil prices and challenge U.S. and Alberta
unconventional oil producers for market share.15

3. Alberta versus Canada and the World?

Part of the Panel's mandate was to compare Alberta's
royalty regime to comparable jurisdictions in Canada and globally
in order to determine its competitiveness.16 In order to
do this, Wood Mackenzie, an international consultancy, was engaged
to complete a fiscal comparative analysis. A full copy of the Wood
Mackenzie analysis with commentary from the Panel is attached to
the Report.17

Generally, the Panel determined that Alberta's royalties are
comparable to similar jurisdictions, but the industry's costs
are substantially higher. Within Canada, Saskatchewan's royalty
regime is more favourable for investment for similar-type
unconventional oil wells, while British Columbia's regime
imposes lower rates than Alberta for natural gas.18

B. THE MODERNIZED ROYALTY FRAMEWORK

The stated goal of the MRF is to create a simpler, more
transparent and efficient royalty system that encourages
investment, creates jobs, and enhances economic activity in
Alberta.

The MRF is divided by industry segments: conventional,
unconventional, oil sands and value-added upgrading. First, all
hydrocarbons (crude oil, liquids and natural gas) will be subject
to a harmonized "revenue minus costs" approach with
changes only applying to new wells spud in 2017 and thereafter (for
wells drilled prior to December 31, 2016, existing royalties will
remain in effect for 10 years).19 Second, Alberta's
oil sands royalty framework will remain unchanged, subject only to
new measures to increase transparency with respect to a
project's allowable capital costs and financial
reporting.20 Third, the Report recommends consideration
of certain value-added partial upgrading investments.

Pursuant to the Panel's report and recommendations, the
Province will adopt the MRF in respect of crude oil, liquids and
natural gas. The MRF will only apply to new wells spud after the
implementation date of the framework (2017), provided however that
a sunset provision will be established to transition exempt wells
into the MRF 10 years from the implementation date of the
framework.

As set out below, the MRF will undertake 5 actions:

Action

Implementation

Harmonized Royalty
Structure

Adopt a single royalty structure, with no differentiation
between produced substances, under which royalty rates are
calculated based on a total review of a blend of all hydrocarbon
products, and all metrics are based in dollars.

Proxy "Revenue
Minus Costs" Structure

Adopt a Drilling and Completion Cost Allowance formula, based
on vertical depth and horizontal length, under which average
drilling costs for new wells will be estimated by proxy.

Institute a flat royalty of 5% on early production revenue up
to the point of payout (payout achieved when the cumulative revenue
from a well is equal to the Drilling and Completion Cost
Allowance). Upon payout, elevated royalty rates will be paid on
subsequent production.

Modify the existing production formula to provide that
declining royalties based on production rates will be triggered
only during the mature phase of a well's life cycle (i.e. once
production drops below a set Maturity Threshold, as determined by a
calibration team, royalty rates will be adjusted downward).

Implement a new proxy cost formula.21

Capital Cost Index

Establish a Capital Cost Index to track year-over-year
inflationary or deflationary changes, and adjust the Drilling and
Completion Cost Allowance annually based on the set Capital Cost
Index.

Index to be set to 100 in 2017, and will "float"
depending on changes in industry costs.

Extend the end date for the Natural Gas Deep Drilling Program
and Emerging Research & Technology Initiative so as to cover
wells drilled in 2016/2017.

Calibration of the
MRF

Establish a team to deliver detailed formulas implementing and
properly calibrating the MRF on or before March 31, 2016.

2. Oil Sands Royalties – Transparency and Public
Reporting

The Panel found that the existing royalty structure for oil
sands used a full revenue minus costs implementation that is
consistent with global constructs for pre-payout and post-payout
profit sharing between operating companies and resources
owners.22 In addition, the current oil sands royalty
framework is poised to deliver significant royalties post payout
(as some projects begin to reach payout in the early
2020s).23

The Panel also concluded that future production growth from the
oil sands is likely to be in the form of smaller-scale in-situ
projects or the expansion of existing projects.24 For
these reasons, the new royalty framework will not affect current
oil sands royalty rates. Instead, changes will be made to the Oil Sands Allowed Costs (Ministerial)
Regulation25 (which sets out the costs
which are deductible when calculating oil sands royalties) in order
to improve transparency, to ensure that companies face stern,
fact-based decision-making in respect of allowable costs, and to
create enhanced predictability, consistency and promptness
regarding decisions in respect of the applicability of cost
rules.

In addition to increased transparency and monitoring of
oil-sands costs, the Panel recommended publication of a financial
summary of each oil sands project, including:

Revenue

Capital Costs

Operating costs

Diluent cost

Return allowance

Realty dollars collected

Gross revenue net of diluent

Net revenue

Gross revenue per barrel

Bitumen production

Royalty rate

3. Exploring Opportunities for Value-Added Processing

The Panel suggested two main opportunities for increased
value-added processing in the Province.

First, the Panel recommended that the Province develop a
value-added natural gas strategy. As part of that process, the
Government is to undertake a review of Alberta's natural gas
options, and develop an action plan to establish a fiscal and
policy framework to encourage investment in value-added activities
for natural gas while maintaining the goal of being a leader in
environmental stewardship.

The second opportunity identified by the Panel concerned
opportunities to accelerate the development and commercialization
of partial upgrading and alternative value-creation technologies
for bitumen.26 The Panel recommended that the Government
undertake a review of such advancements, and highlighted that the
success of such technology investments would enable Alberta to
realize expanded crude marketability, expanded export capacity and
a lower environmental footprint for a portion of the Province's
bitumen production, as well as hedge against a future in which
transportation fuel demand is disrupted.

C. TIMELINE AND KEY DATES

The following timeline and list of key dates assumes that the
Alberta Government will implement all recommendations proposed
within the Report in accordance with the suggested timeframes. As
such, this summary should be used only as an outline of the
anticipated timelines pending confirmation from Alberta Energy.

Date

Action
Item

March 31, 2016

Expiration of Calibration Period for the finalization of
specific formulas, parameters and MRF procedures.

Calibration Team to finalize:

the Drilling and Completion Cost Allowance (C*) formula;
and

the post-payout price functions (royalty rates) within the
constraint of matching average, expected industry returns and
Albertans' share of value that are achieved under the current
framework.

March 31, 2016

Full details of the MRF to be released.

Details to include any allowances in the MRF to accommodate
sharing of the carbon levy.

March 31, 2016

Announcement of strategic programs for enhanced recovery and
high-risk experimental wells (to be announced simultaneously with
the details of the MRF).

March 31 Annually

Public announcement of Alberta's Capital Cost Index for
application on April 1 of the same year.

November 2016

Expiry of Natural Gas Deep Drilling Program.

Note that the Panel has recommended that this program be
extended to 2017, in order to cover wells drilled in
2016.27

December 31, 2016

Deadline for Alberta Energy review of the Otherwise Flared
Solution Gas Royalty Waiver Program to ensure it is adequately
adjusted to the Climate Leadership Plan.

June 2018

Expiry of Emerging Research & Technology Initiative.

Note that the Panel has recommended that this program be
extended to 2017, in order to cover wells drilled in
2016.28

[16] Report at 46-47. The Panel used two criteria to
determine which jurisdictions should be used in the comparative
fiscal analysis. The two criteria were: (i) comparable resources
(i.e. similar geologic play types similar in character and scale to
Alberta) and (ii) capital competiveness (Wood Mackenzie considered
only jurisdictions open for free market investment to companies
currently operating in Alberta). The following competitor and
comparator groups were selected: Natural Gas: British Columbia,
Pennsylvania, Ohio, Texas, United Kingdom; Crude oil and liquids
– Saskatchewan, Colorado, North Dakota, Oklahoma, Texas,
Argentina, Colombia; Oil sands – California, Madagascar,
Oman, Venezuela, Newfoundland and Labrador, Alaska, Deepwater Gulf
of Mexico, Brazil, Kazakhstan, Norway.

[21] Report at 61, Figure 21 (formula equal to C*
=a1*(TVD)+a2*(TVD-V deep)+a3*(TVD*TLL), where: (i) TVD is the true
vertical depth of the well; (ii) Vdeep is the vertical depth
threshold applicable to all wells, beyond which a well begins to
receive additional capital cost allocation; (iii) TLL is the Total
Lateral Length; (iv) a1 is a capital cost allocation for every
meter drilled vertically; (v) a2 is a capital cost allocation for
every vertical meter drilled deeper than Vdeep; and (vi) a3 is a
capital cost allocation for every meter drilled horizontally, for
every meter drilled vertically).

[22] Report at 52.

[23] Report at 80.

[24] Report at 37.

[25] Alta Reg 231/2008 (the Panel also recommended
consultation regarding any changes to this regulation to ensure
that any chances reflect current market conditions and
Alberta's overall strategy, Report at 66).

[26] Report at 13 (at a high level, partial upgrading is
the processing of bitumen to reduce the thickness by removing
proportions of the heaviest fraction of the bitumen barrel.
Partially upgraded bitumen can flow in a pipeline with little or no
diluent, which can increase export pipeline capacity by as much as
30%).

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